Page 1142 – RTO Insider

February 5, 2020

SPP MMU: Reduce Self-Commitments, Improve Market

By Tom Kleckner

S P P‘s Market Monitoring Unit said it is not looking to end self-commitment but that a reduction in the practice would result in a more efficient market.

SPP — MMU Executive Director Keith Collins | © *RTO Insider*

“We do note that a high volume of make-whole payments [for self-commitments] is not considered desirable. It creates inefficiencies in the market,” Monitor Executive Director Keith Collins said Monday during a webinar on a report it released in December on self-commitments.

Collins capitalized on the previous day’s Super Bowl to put the issue into terms that might make more sense to his audience. “Imagine your favorite sports team, and imagine it’s the players who decide will play, rather than the coach,” he said. “The outcome you get may not be as efficient as the coach optimizing that for you.”

In the re p ort, “Self-committing in SPP markets: Overview, impacts, and recommendations,” the Monitor recommends SPP and stakeholders work to reduce the number of self-commitments to improve price formation and market efficiency. The Monitor also suggests SPP modify its market design by adding another day to the market optimization period.

MW dispatched by commitments, self-commit MWs by fuel type | *SPP MMU*

The report says a smaller distortion of prices and investment signals “will likely help market participants make better short-run and long-run decisions, which tends to coincide with improved profit maximization.

“Enhanced profit maximization, combined with effective regulation and monitoring, will likely lead to ratepayer benefits in the form of cost reduction,” the Monitor said.

Monitor staff studied offer behavior from March 2014, when SPP’s day-ahead Integrated Marketplace went live, to August 2019. They re-solved past market cases by running two simulation series of a week per month from September 2018 to August 2019, assuming all generation was offered in market status and that it could be started economically by the day-ahead market.

The analysis found that:

The volume of self-committed MW has declined over time but remains nearly half of the total MW volume generated during the study’s time frame.
Prices and production costs were systematically lower when at least one self-committed unit was on the margin.
In almost all cases, self-committed generators had lower revenues because of negative congestion prices. Market-committed generators typically had a more balanced congestion profile.
Resources with long lead times and/or high start-up costs tended to be self-committed instead of market-committed.
Self-committed units generally had much higher capacity factors than those that are market-committed. The largest portion of self-committed dispatch MW were from coal units, exceeding the second-largest fuel type by a 4-to-1 ratio.

In its simulations, the Monitor found that:

When the market made unit commitment decisions and lead times were unchanged, both market-wide production costs and market-clearing prices for energy increased.
When the market made unit commitment decisions and lead times were modified to allow the day-ahead market to commit the resources with long lead times, market-wide production costs were essentially unchanged and market-clearing prices for energy increased about 7% ($2/MWh) on average. Congestion prices fluctuated from -$1/MWh to $1/MWh on average.

Having the economic commitment process solve over a two-day period rather than one would optimize long-lead time resources’ participation in the market, the report says.

“Simply eliminating self-commitment without any additional changes could result in an increase in total production costs,” the report warns. “However, when lead times were shortened to reflect an additional day in the market optimization and self-commitment was eliminated, producers were paid more and production costs declined.”

The Monitor is taking its presentation on the road. Having already shared its recommendations with the Market Working Group, it also plans to meet with the Cost Allocation Working Group.

“We’ll be speaking in different committees and venues,” Collins said.

February 5, 2020

GridLiance Gains Entry into MISO

By Amanda Durish Cook

Transmission owner GridLiance Heartland has gained access to the MISO system through an acquisition of transmission lines in Illinois and Kentucky after an unsuccessful first attempt to join the RTO.

In a trio of orders Jan. 31, FERC conditionally approved GridLiance Heartland’s acquisition of eight transmission assets from Vistra Energy subsidiary Electric Energy Inc. (EEI) (E C 20-13), set an annual transmission revenue requirement at about $7.4 million (ER19-2 0 50-002) and OK’d a separate open access transmission tariff (OATT) for the two lines that won’t be under MISO functional control immediately (ER19-2092, e t al.).

The third order also established settlement judge proceedings to examine the reasonableness of GridLiance Heartland proposing the MISO base return on equity in the OATT for non-MISO assets. GridLiance proposed a 10.32% ROE for the OATT, the ROE rate in use in MISO at the time of its filing in December 2018. FERC in late November adopted a new 9.88% return on equity for transmission owners. (See FERC Adopts ROE Methodology in MISO Complai n ts.)

The deal involves two 161-kV substations and six 161-kV transmission lines 8-10 miles in length that cross the Ohio River and connect to the EEI-owned Joppa Power Plant in southern Illinois. Vistra owns an 80% interest in EEI, with Kentucky Utilities controlling the remaining 20%. The assets are currently outside the MISO footprint. GridLiance said it would transfer all assets to MISO control by 2022: Four of the six lines will be turned over immediately to MISO, while two must wait for existing power supply agreements to run their course.

The six lines were originally constructed to power the U.S. Department of Energy’s now-defunct Padu c ah Gaseous Diffusion Plant uranium facility. EEI reconfigured its transmission system to disconnect from the Paducah plant in 2017. Four of the lines connect with TVA, while the other two connect with the Louisville Gas & Electric/Kentucky Utilities balancing authority area. The lines currently don’t serve any load.

GridLiance MISO — Paducah Gaseous Diffusion Plant | *U.S. Department of Energy*

MISO’s Board of Directors approved GridLiance Heartland’s application to join the RTO as a transmission-owning member in September 2018 subject to the outcome of the proposed transaction.

FERC had blocked the transaction in August, deciding GridLiance and EEI failed to prove the acquisition wouldn’t adversely affect MISO rates. (See FERC Blocks GridLiance’s Door into MISO.) The move will increase revenue requirements in the Ameren Illinois transmission pricing zone by about 2.6%.

GridLiance proposed rate mitigation credits to offset the $3.6-million difference between the projected revenue requirements of EEI and itself. The TO said the credits would appear in accounting as a fixed revenue credit and lower its revenue requirement every year for the five years after MISO takes control of the lines.

GridLiance said the credits “balance the risks and rewards for a start-up transco with a small initial rate base.” It also noted that it plans to participate in “proactive” planning studies on how the lines “may be optimized to solve documented transmission constraints.” The company said the lines may prove useful in lessening the strain on the transfer constraint linking MISO’s Midwest and South subregions.

GridLiance also noted that as a MISO member, it could help address “underinvestment” in transmission by MISO’s municipal and cooperative utilities.

Ameren Objects

The commission approved the deal over multiple objections from Ameren.

Ameren faulted GridLiance for using estimated, “snapshot in time” revenue requirements for its rate credits rather than actual amounts. It also said the commission was failing to consider that GridLiance would seek recovery of its $23.6 million regulatory asset that FERC approved last year. Ameren asked that FERC create further protections from the impact of GridLiance’s regulatory asset costs.

The company also said GridLiance’s claims of future benefits to MISO or the Ameren pricing zone were “tenuous.”

But FERC said GridLiance’s rate mitigation proposal addressed its concerns over the rate increase. The commission also said GridLiance Heartland is not to recover any amounts related to its regulatory asset during the first five-year rate mitigation.

“The regulatory asset is related to past development activities by GridLiance Heartland and not to costs that [EEI] would have incurred if it had retained ownership,” FERC warned.

FERC accepted GridLiance’s unorthodox rate mitigation proposal instead of the more commonplace five-year rate freeze based on the company’s assertation that forces out of its control could have increased even EEI’s revenue requirement, such as storm damage, or a new NERC requirement.

Ameren also protested the use of a stand-alone OATT for the non-MISO lines, saying it represented a “step backward in terms of the efficiencies created by having an RTO footprint.”

“We are not persuaded by Ameren’s argument that this proposal is a step backwards because GridLiance Heartland is eschewing the efficiencies of an RTO footprint. RTO participation is not mandatory and Order No. 888 requires that an OATT be on file in order to provide transmission service,” FERC responded.

GridLiance said it also plans to use the OATT to provide transmission service over “any future facilities it acquires in the MISO region but does not transfer to MISO’s functional control.”

FERC granted a one-time waiver of Order 1000’s competition requirements for the OATT. The commission said since GridLiance is proposing to transfer control of the lines and substations to MISO, it afforded no “practicable opportunity” for the TO to adhere to Order 1000. The commission noted the “unique circumstances” present in the transaction and said the waiver would be reassessed if GridLiance decides to build additional facilities under the same OATT.

February 5, 2020

New Agreement Swaps COTP Access for CAISO CRRs

By Robert Mullin

FERC approved an agreement that will allow the Transmission Agency of Northern California (TANC) to convert capacity on a key transmission line into “option” congestion revenue rights in the CAISO market (ER20-3 9 8).

The agreement covers use of TANC’s California-Oregon Transmission Project (COTP), a 340-mile, 500-kV line capable of delivering up to 1,600 MW of energy from Southern Oregon into Northern California. The line is jointly owned by the Western Area Power Administration and members of the Balancing Authority of Northern California (BANC), the BA for a handful of publicly owned California utilities located outside CAISO’s territory, including Sacramento Municipal Utility District.

Completed in 1993, the COTP was built to parallel the older Pacific AC Intertie (PACI). Together the lines comprise the California-Oregon Intertie (COI), a 4,800-MW transmission corridor linking Northern California with the hydro- and wind-rich Pacific Northwest. In 2013, PacifiCorp executed a similar CRR agreement with CAISO over use of the PACI portion of the COI, which CAISO manages as transmission operator.

The new agreement grants TANC access to “option” CRRs, a financial instrument that enables its holder to collect a positive revenue stream for allowing use of transmission capacity. The more common “obligation” CRRs come with risks, namely that they can provide holders with either a positive or negative revenue stream depending on the congestion pattern on a line.

The agreement stipulates that TANC will notify CAISO 30 days ahead of each calendar month regarding the volume of COTP transmission capacity the agency will release for conversion to the special type of CRRs. Capacity will be released on a directional basis (either north-to-south or south-to-north). CAISO will then issue TANC option CRRs that will source and sink at either Bonneville Power Administration’s Captain Jack substation or the Tracy 500-kV CAISO scheduling point, depending on the direction of the release.

The ISO will settle TANC’s CRRs as option CRR payments for intervals when the day-ahead market shows a congestion price difference between the source and sink, but payments will not be issued for real-time congestion. TANC capacity not converted to CRRs will remain as transactions subject to TANC’s transmission tariff.

CAISO’s Nov. 18 filin g touted the broad benefits of the agreement for its market participants.

“To the extent that TANC releases portions of the TANC capacity on the COTP for use by the CAISO, the ability of CAISO market participants to schedule transactions on the COI will increase and the CAISO will be able to address congestion more efficiently and reliably,” CAISO wrote. “The agreement provides CAISO market participants more transfer capability from the Pacific Northwest and an alternate path to the PACI. This is a more efficient outcome that increases flexibility.”

CAISO also said the agreement would not affect the financial position of existing CRR holders.

“The total amount of capacity that potentially could become TANC CRRs is equal to the total amount of capacity reserved for the TANC capacity. The agreement simply makes the available capacity easier to use by the entire CAISO market,” the ISO said.

PG&E Concerns Rebuffed

In approving the agreement on Jan. 31, FERC dismissed the concerns of Pacific Gas and Electric, which acknowledged the benefits for CAISO participants, while also contending that the monthly nature of the agreement differed from that of the deal with PacifiCorp and could incentivize TANC to release capacity in a manner that will maximize its own financial benefit.

The commission found no “meaningful distinction” between the TANC and PacifiCorp agreements despite that difference.

“As CAISO notes, the agreement provides an incentive to TANC to release transmission capacity during months when congestion revenue rights are most valuable, and it is during these months that the transmission capacity has the greatest potential to benefit market participants,” the commission said. “Further, TANC must commit to the capacity being released for the entire period.”

FERC also rebuffed PG&E’s argument that the agreement is predicated on modeling transmission capacity in a way that would effectively give priority to TANC to elect its CRR allocation before other participants in the normal election process. The commission noted that the agreement’s modeling of CRR options is consistent with how CAISO models options in the PacifiCorp agreement.

The commission additionally rejected PG&E’s request that the TANC agreement be limited to a two-year term and declined the utility’s recommendation for annual reporting to FERC.

“In light of the information on released transmission capacity available through CAISO’s OASIS, we find no need for CAISO to file similar information with the commission,” FERC concluded.

February 4, 2020April 9, 2024

MOPR Ruling Threatens to Upend Self-supply Model

By Christen Smith and Rich Heidorn Jr.

Old Dominion Electric Cooperative, which supplies power to 1.4 million people in Virginia, Maryland and Delaware, has been generating its own power since 1983, when it bought a share of Virginia Electric and Power Co.’s North Anna Nuclear Power Station.

It would add the 433-MW coal-fired Clover Power Station in 1995/96, and more than 1,600 MW of natural gas capacity in 2001-2004. Less than two years ago, it began operating the 1,000-MW Wildcat Point combined cycle plant. As a result of its investments, it got 64% of its energy and 88% of its capacity from its own assets in 2018.

But because of Is Self-Supply Suppressing Prices?)

Attack on Business Model

ODEC and other self-supply load-serving entities (LSEs) argue the order will unravel their business model and undermine their roles in local economic development. The National Rural Electric Cooperative Association (NRECA) and East Kentucky Power Cooperative (EKPC) called the expanded MOPR a “frontal attack” on practices used by cooperatives for decades.

“The longstanding business model of electric cooperative LSEs is to invest in generation for their long-term load obligations, not the short-term forward capacity construct,” ODEC said in its Jan. 21 rehearing request (EL16-49, EL18-178). “Therefore, capacity which might be excess to an LSE’s reliability requirement in the early years of a resource will decline in later years as load grows. This does not make the investment ‘uneconomic.’” (See PJM MOPR Rehearing Requests Pour into FERC.)

ODEC joined PJM in 1998 to aid in the delivery of power to its three member distribution cooperatives on the Delmarva Peninsula. But its wholesale power contracts (WPCs) with all of its 11 members have been on file with FERC as far back as 1992.

“Most if not all of these [WPCs] originated well before PJM’s capacity construct and MOPR” in 2006, the National NRECA and EKPC said in their own rehearing request.

Their filing referenced the Supreme Court’s 2016 ruling in Hughes v. Talen, which said states were free to subsidize new generation “through measures untethered to a generator’s wholesale market participation.”

“There can be no legitimate conclusion that the WPCs are directed at or tethered to the operation of generating resources in PJM’s capacity construct,” NRECA and EKPC said.

Economic Development Threatened

EKPC, which joined PJM about seven years ago, said it signed on “to bring the benefits of a competitive wholesale market” to its 16 member co-ops in Kentucky. “These benefits have made it possible to attract new commercial and industrial customers to locate in Kentucky,” it said.

EKPC said its economic development efforts are threatened by the expanded MOPR, which also appears to cover new demand response resources and renewable generation with voluntary renewable energy credits (RECs). EKPC filed a “green tariff” proposal with the Kentucky Public Service Commission in 2019 in response to increased customer interest in “renewable or sustainable” resources.

“The application of the MOPR to resources supporting voluntary clean energy initiatives may discourage new industries from locating in the PJM region of Kentucky despite the great efforts EKPC is making to advance economic development in the commonwealth of Kentucky,” EKPC said. “The December 2019 order may frustrate EKPC’s opportunity to court new industries seeking to ensure that their energy needs are met with renewable resources.”

EKPC, which sells DR from nine end-use customers into the capacity market, said one industrial load has invested millions to increase its DR capability. EKPC included the expansion in the DR plan for the 2022/23 Base Residual Auction, which has not been held because of the MOPR litigation. “It is unclear whether that capability will be considered to be existing and eligible for the exemption provided in the December 2019 order,” EKPC said.

No Longer ‘Residual’ Market

FERC approved PJM’s Reliability Pricing Model (RPM) and its BRAs in 2006 to procure capacity “after LSEs have had an opportunity to procure capacity on their own” and “as a last resort.”

EKPC said FERC’s ruling was “the most drastic and likely most destructive measure taken by the commission to date” in its attempt to transform PJM’s “resource adequacy market away from a residual capacity auction … to a mandatory sole source for PJM and its LSEs to meet regional capacity obligations.”

“The chilling effect this order will have on investment in new self-supply resources will convert PJM’s capacity market from a ‘Base Residual Auction,’ designed to procure capacity not otherwise procured through self-supply, to an auction in which capacity purchases from the market will be the only viable option for all LSEs, thus eviscerating the self-supply option,” North Carolina Electric Membership Corp. said in its rehearing request.

Expanding MOPR to public power self-supply resources is based on the “mistaken premise that all resource entry and exit must be coordinated solely by the RTO-administered market to be deemed economic,” consultant Marc D. Montalvo said in comments filed on behalf of the American Public Power Association (APPA) during the commission’s paper hearing on the docket.

“RPM is a mandatory resource adequacy construct that offers a single product, and ‘competitive’ prices are determined by PJM applying cost development guidelines with no empirical link to actual market conditions or consumer decisions,” said APPA, American Municipal Power (AMP) and Public Power Association of New Jersey (PPANJ). “Ironically, by its latest action, the commission has removed any remaining genuine market component of RPM by requiring all ‘competitive’ offers to be determined administratively in Valley Forge, Pa.”

MOPR History

The MOPR was introduced along with RPM in 2006. It does not apply to baseload resources that required more than three years to develop (nuclear, coal and integrated gasification combined cycle facilities), hydroelectric facilities, or any upgrade or addition to an existing generator. Also exempt was any new entry being developed in response to a state regulatory or legislative mandate to resolve projected capacity shortfalls for the delivery year.

In 2011, FERC approved revisions eliminating the state mandate exemption and adding a unit-specific review process to consider cost justifications submitted by resources whose sell offers fell below the established floor. Wind and solar facilities were also added to the list of resources permitted to make zero-priced offers; additions to existing capacity resources were no longer exempted.

In 2013, FERC approved a categorical exemption for self-supply for public power and vertically integrated utilities, subject to net-short and net-long thresholds. The commission also agreed to exempt “competitive entry” units that could prove they received no out-of-market funding other than that resulting from competitive auction.

But in 2017, the D.C. Circuit Court of Appeals remanded the 2013 order, saying the commission had exceeded its authority in modifying PJM’s proposal by retaining the unit-specific review process, which the RTO had wanted to eliminate. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)

The commission responded by returning to the market design in effect before the 2013 MOPR proceeding, which applied the MOPR to all new, nonexempted gas fired resources but allowed zero-priced offers by nuclear, coal, wind solar and hydro. (See On Remand, FERC Rejects PJM MOPR Compromise.)

That set the stage for the commission’s June 2018 order, which declared the MOPR unjust and unreasonable for failing to address price suppression from growing state subsidies for nuclear and renewable resources. (See FERC Orders PJM Capacity Market Revamp.)

FRR not an Option

FERC said self-supply entities “remain free” to provide for their own resource adequacy through the existing fixed resource requirement (FRR) alternative.

But APPA, AMP and PPANJ say that neither the FRR option nor the unit-specific review process is a “reasonable accommodation” for self-supply.

They cited a 2014 ruling by the 3rd U.S. Circuit Court of Appeals that “participating in the FRR option is an all-or-nothing proposition and appeals as a practical matter only to large utilities that still follow the traditional, vertically integrated model.”

Public power LSEs’ capacity needs can change over time as they add new members, if new locational deliverability areas (LDAs) are added or their boundaries change, the groups noted. “The creation of a new binding Cleveland LDA could impact 100% of the municipality’s load, whereas only a portion of the load of FirstEnergy, would be impacted,” they said.

“The FRR may not be a workable alternative for smaller LSEs, given the requirements to opt out of the capacity construct for both purchases and sales, for a five-year period with onerous financial consequences if the ability to do so becomes untenable,” ODEC said.

The unit-specific exemption only offers an alternative to the default offer floor, APPA, AMP and PPANJ said. Resources using the unit-specific exemption must still bid above an administratively determined level, leaving them at risk of not clearing the auction.

They cited the example of Delaware Municipal Electric Corp. (DEMEC), which was required to use a unit-specific exemption to qualify a then-new gas-fired generator in 2011 for the 2014 BRA. They said PJM’s Independent Market Monitor sought to add 200 basis points to DEMEC’s actual financing rate. After negotiations, DEMEC and the Monitor agreed to a mitigated offer “substantially” higher than what the company had planned to bid.

“Fortunately, DEMEC’s offer price for the new resource did clear the 2014 BRA. However, had DEMEC acceded to the IMM’s original proposed upwardly mitigated offer price, DEMEC’s generation resource would not have cleared the 2014 BRA, thereby stranding DEMEC’s investment and causing irreparable harm to DEMEC and its communities,” the groups said.

EKPC said it and other co-ops have been snared in a catch-22.

“Since the commission broadly swept the cooperative electric utility business model into the definition of state subsidy, it is not clear how an electric cooperative could certify that it is foregoing receiving the state subsidy in order to take advantage of the competitive offer exemption,” it said. It asked the commission to clarify how PJM should apply the competitive exemption to co-ops. It also sought rehearing of the commission’s determinations that voluntary RECs are state subsidies and that the MOPR should apply to DR.

“Regardless of the characterization of the MMU’s actions in a prior 2011 MOPR review, the MMU reviews unit specific MOPR requests under the existing rules based on unit specific details, including the cost of capital,” IMM Joe Bowring said in response. “The MMU has always respected the public power business model and recognizes that the cost of capital for public power entities is not the same as it is for private entities. The commission, in [the December] order, has not stated that the financing options of public power entities constitute a state subsidy.”

Fear of ‘Balkanization’

EKPC said blocking vertically integrated utilities from seeking a competitive exemption for future resources “will have a negative impact on the existing market and will hamper future prospects of growing the PJM wholesale market to include new territories.”

“Given the 10 cooperatives and three vertically integrated utilities that currently participate in the capacity market, EKPC is concerned about the potential for balkanization in the PJM region if many or all of these entities utilize the FRR alternative as the better way to satisfy their load-serving obligations.”

The Brattle Group had expressed similar concerns in a 2011 report for PJM, saying that not clearing self-supplied resources would “make it more difficult and costly to hedge capacity prices and will likely force many load-serving entities that rely on self-supply to opt out of RPM through the FRR option. More widespread use of the FRR option would reduce market efficiency and increase costs.”

February 4, 2020February 18, 2025

EIM Reports $60M in Q4 Benefits

By Hudson Sangree

CAISO’s Western Energy Imbalance Market delivered more than $60 million in benefits to its participants in the fourth quarter of 2019, bringing the total benefits of the interstate real-time market to nearly $862 million since it began operating in November 2014, the ISO announced Thursday.

The biggest beneficiary among the EIM’s nine active participants was Arizona Public Service, which saved $17.4 million in in the last three months of 2019, followed by PacifiCorp and Portland General Electric, each of which saw approximately $11 million in benefits, CAISO said.

“When we launched the Western EIM, we knew it would be a win for consumers,” CAISO CEO Steve Berberich said in a statement. “These benefits prove that increased coordination creates operational savings and greater integration of variable resources to meet the evolving demands of consumers.”

November marked the EIM’s fifth anniversary. By 2022, it’s expected to serve 77% of load in the Western Interconnection with 11 more participants scheduled to join in the next three years. Arizona’s Salt River Project and Seattle City Light will enter the market this year.

The utilities scheduled to join in 2021 include the Los Angeles Department of Power and Water, Public Service Company of New Mexico and NorthWestern Energy. The Bonneville Power Administration and three other entities are expected to join in 2022.

In December, four Colorado utilities — Xcel Energy, Black Hills Colorado Electric, Colorado Springs Utilities and Platte River Power Authority — announced they will join the EIM as soon as 2021, filling in part of the last Western state that’s currently blank on the EIM map. (See EIM Lands Xcel, 3 Other Colo. Utilities.)

It also represented a major win over the EIM’s nascent competitor, SPP’s Western Energy Imbalance Service, which has sought to attract utilities unhappy with the idea of forming close ties with California and CAISO. The economic benefits of the EIM, however, have attracted participants even from more conservative states of the interior West.

In its latest quarterly report, CAISO said the financial benefits derive mainly from transfers across balancing areas, “providing access to lower-cost supply, while factoring in the cost of compliance with greenhouse gas emissions regulations when energy is transferred into the ISO.”

“EIM uses state-of-the-art technology to find and deliver low-cost energy to meet real-time demand across eight Western states and extends to the border with Canada,” it said. “The Western EIM has proven extensive financial and operational benefits since its inception in November 2014, and cumulative gross economic benefits now total $861.79 million.”

Trading now occurs only in the 15-minute and real-time markets, but through its stakeholder initiatives, the EIM is evaluating expanding to a day-ahead market and studying the potential for participants to benefit from wheel-through transfers, a proposal that’s proven controversial in the past. (See EIM Members Wary of Need for CAISO Wheeling Charge.)

“Currently, an EIM entity facilitating a wheel-through receives no direct financial benefit for facilitating the wheel; only the sink and source directly benefit,” the EIM said its Q4 report. “As part of the Western EIM Consolidated Initiatives stakeholder process, the ISO committed to monitoring the wheel-through volumes to assess whether, after the addition of new EIM entities, there is a potential future need to pursue a market solution to address the equitable sharing of wheeling benefits.”

February 4, 2020

FERC Order Keeps Z2, Aids EDF’s Sponsored Project

By Tom Kleckner

SANTA FE, N.M. — FERC on Friday rejected SPP’s request to eliminate Z2 revenue credits for sponsored transmission upgrades, allowing the RTO to submit a revised proposal for the commission’s consideration without a cap limiting the terms and potential value of the credits’ replacement (ER20-453).

SPP had proposed using incremental long-term congestion rights (ILTCRs) instead, but the commission found modifications to the existing ILTCR compensation term to be unjust and unreasonable. The grid operator had suggested changing the compensation from a range of 10 to 20 years, to 20 years or until the upgrade sponsor recovers the directly assigned upgrade costs with interest, whichever occurs earlier.

FERC noted it previously found that “a similar cap on recovery only up to the cost of the facility would not serve as an incentive for entities to build merchant transmission projects and that an LTCR could provide such an incentive if the value of the LTCR is greater than the cost of the investment.”

Under Attachment Z2 of SPP’s Tariff, sponsors that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.

Stakeholders in October approved the elimination of Z2 credits, to be replaced by ILTCRs. Several stakeholders opposed the decision, saying they wanted to wait until SPP could fully develop the ILTCR mechanism. (See “Stakeholders Endorse Eliminating Z2 Revenue Credits,” SPP MOPC Briefs: Oct. 15-16, 2019.)

SPP Z2 revenue credits — The Pauline-to-Hastings sponsored upgrade | *SPP*

‘Sandbagged’

The FERC decision short-circuits an animated discussion that erupted over a $12 million sponsored upgrade during SPP’s Board of Directors meeting on Jan. 28. Nebraska Public Power District pulled the upgrade from the consent agenda, asking to delay an approval vote until April to ensure that “financing issues” are worked through and that the agreement complies with IRS regulations and Nebraska law.

EDF Renewable Energy, the project’s sponsor, questioned NPPD’s concerns, saying they could have been dealt with sooner. The project had already been endorsed by the Markets and Operations Policy Committee during its Jan. 14-15 meeting.

“I’m curious as to what needs to be done here,” said EDF legal counsel Dan Simon, calling in to the board meeting. “It sure seems like there’s been some intention to delay here.”

Simon’s ire was raised by NPPD’s suggestion to delay negotiations over the project, which involves reconductoring and rebuilding 13 miles of 115-kV line in southern Nebraska. EDF plans to pay for the upgrade, which would be a creditable upgrade eligible for cost recovery through Z2 credits rather than ILTCRs.

Given that SPP had asked for a Feb. 1 effective date in its filing before FERC, Simon’s frustration was understandable. “It sounds like a tactical way at the last minute to preclude us from getting Z2 credits,” Simon said, alleging EDF had been “sandbagged.”

“All this gets back to the Z2 issue,” he said.

NPPD’s Tom Kent, who chaired the Holistic Integrated Tariff Team that recommended eliminating Z2 credits, responded as Board Chair Larry Altenbaumer tried to bring the discussion to a close. (See SPP Board Approves HITT’s Recommendations.)

“I totally disagree with the characterization that [Simon] made,” Kent said. He noted NPPD had no intent to delay the project.

FERC’s rejection would seem to give EDF a clearer path to meet a Dec. 5 deadline to execute its agreement with NPPD and be eligible for a notification-to-construct from SPP.

The board eventually endorsed the sponsored upgrade, directing staff to work with NPPD and EDF to negotiate an agreement for the project.

“SPP has an obligation to ensure that whatever needs to be done is done consistently with what the legal requirements are and consistent with the parties’ negotiating and addressing that,” Altenbaumer said. “The goal … is to direct staff to get this across the finish line as expeditiously as possible.”

The board discussion was briefly interrupted by the Eldorado Hotel & Spa’s fire alarm system. Stakeholders briefly vacated the meeting room, jokingly blaming the false alarm on NPPD.

That led Altenbaumer to later say he had received some “really good advice”: reviewing safety protocols before the start of each meeting. “That’s good guidance,” he said.

February 4, 2020

Draft Climate Bill Would Make RTO Membership Mandatory

By Michael Brooks

House Democrats last week released a draft bill that received attention for its ambition to set a national clean electricity standard, requiring utilities to get 100% of their power from net-zero-emission resources by 2050.

But tucked away in the 622-page draft Climate Leadership and Environmental Action for our Nation’s (CLEAN) Future Act is a provision making it mandatary for utilities to join an ISO or RTO.

Section 217c of the bill (page 91) would amend Section 202a of the Federal Power Act, which gave FERC the power to approve RTOs, by removing the word “voluntary” and adding: “The commission shall require each public utility to place its transmission facilities under the control of an ISO or an RTO not later than two years after the date of enactment of the CLEAN Future Act.”

The provision is part of a larger series of desired changes at FERC, reading as a wish list for Democrats and the agency’s critics.

Draft Climate Bill — Rep. Frank Pallone (D-N.J.), chair of the House Energy and Commerce Committee, announced the framework for what would become the CLEAN Future Act on Jan. 17. | *Frank Pallone*

The bill would create an Office of Public Participation and Consumer Advocacy at FERC; clarify that the commission must consider climate change in its environmental assessments of natural gas pipelines; prevent pipeline companies from using eminent domain until they have obtained all necessary federal and state permits; and allow the commission to approve carbon pricing regimes for wholesale power.

Perhaps as, if not more, significant than the RTO provision is a directive that would require FERC to conduct a rulemaking to increase the effectiveness of interregional transmission planning. Section 212 of the bill spells out what exactly this would entail, directing the commission to emphasize that “interregional benefit analyses made between multiple regions should not be subject to reassessment by a single regional entity” and “the elimination of arbitrary voltage, size or cost requirements for an interregional transmission solution,” among other requirements.

The bill would also require FERC to submit a report on its efforts to encourage deployment of technologies that increase transmission efficiency, such as dynamic line ratings.

Clean Energy Credits

The draft bill is an ambitious, sweeping plan to dramatically reduce the country’s emissions and address global climate change that includes requirements for states, FERC, EPA and the Department of Energy, and targets emission reductions from the grid, vehicles and buildings.

The core provision of the bill would require utilities to begin transitioning to net-zero-emission electricity in 2022, giving them 28 years to reach 100%.

This would be facilitated by a clean energy credit trading program, established by DOE, that would function similar to existing state renewable energy credit programs, but the department would dole out credits to generators based on their carbon intensity, not on their resource type. Non-emitting resources would receive credits equal to the amount of megawatt-hours they sell. Generators that emit less than 0.82 metric tons of CO2/MWh would be eligible for credits based on how far below the threshold they are, incentivizing their owners to clean them up.

Utilities would then be required to purchase credits from generators and submit a certain amount, increasing each year, to the department. Utilities that fail to submit enough credits would be subject to a penalty.

While the overall bill drew praise from environmental groups, their reaction to the credit trading program was mixed.

“This broad legislative package includes some policies that would be clear steps forward to address the climate crisis, but it’s concerning that on what is perhaps the central question of climate policy — what counts as clean energy — this bill includes options that could leave a door open to gas and coal,” the Sierra Club said.

The criticism from environmentalists could mean the bill would face some pushback from the more liberal wing of the party, which has supported more aggressive decarbonization plans such as the Green New Deal.

“The legislation includes a national clean energy standard that could be transformational if designed well,” said Rob Cowin, director of government affairs for the Union of Concerned Scientists’ Climate and Energy program. “A national clean energy standard must not increase our reliance on natural gas generation, as natural gas use economywide now contributes more to U.S. carbon emissions than coal. We will continue to work towards enacting legislation consistent with the science and that will provide a just and equitable transition to a clean energy economy.”

“This credit system would encourage emissions reductions through changes in dispatch or investments at a facility, consequently further reducing emissions and lowering costs by allowing low-carbon technologies to participate,” nonprofit Resources for the Future said in a brief on clean energy standard published a year ago.

“The provision of credits to clean resources will likely create an incentive to expand energy supply and consequently lead to lower wholesale market prices. This effect notably differs from that of a carbon price, which would likely raise wholesale prices,” RFF said. “The extent to which decreased wholesale market prices will lead to lower retail prices could vary with the policy target but would be especially likely when customers are served by a vertically integrated utility that generates more clean energy credits than it needs to comply with the standard.”

It is unclear if Democrats intend to introduce the bill this year given its assured death in the Republican-controlled Senate and the upcoming elections. In its press release announcing the draft, the House Energy and Commerce Committee only said that “as it continues to expand and refine” the draft, “hearings and stakeholder meetings will continue throughout the coming year.”

“The CLEAN Future Act treats this climate crisis like the emergency that it is, while also setting the foundation for strengthening our economy and creating good paying jobs for a clean and climate-resilient future,” committee leaders said. “We look forward to continuing to work with all impacted stakeholders on this proposal in the coming months.”

Republicans are also planning to release their own bills to address climate change, as soon as this week. The package aims to boost research and development funding in nuclear energy and carbon capture, as well as increase tree planting. Legislation being drafted by Rep. Bruce Westerman (R-Ark.) would commit the U.S. to planting some 3.3 billion trees each year over the next 30 years.

February 4, 2020

CPUC Proposes New Power Shutoff Guidelines

By Hudson Sangree

The California Public Utilities Commission issued proposed guidelines Thursday for utilities to follow in the 2020 fire season when intentionally blacking out areas to prevent electrical equipment from starting wildfires.

At the same time, CPUC President Marybel Batjer issued a ruling calling Pacific Gas and Electric’s reporting to the commission on its public safety power shutoffs (PSPS) “fundamentally inadequate” in detail and substance and ordering it to immediately fix the situation.

“PG&E’s performance during PSPS events in 2019 was unacceptable and cannot be repeated in 2020,” Batjer said in a statement. “The reports that I ordered PG&E to submit are part of the CPUC’s comprehensive review of the 2019 PSPS events.”

The proposed guidelines, issued for public comment, would require the state’s investor-owned utilities to restore power no more than 24 hours after the end of weather conditions that led to a safety shutoff. The IOUs would also have to convene monthly regional workshops with local governments and others on fire safety practices and to conduct PSPS exercises with public safety agencies in fire-prone areas.

The proposed PSPS guidelines would augment the guidelines established by the CPUC in a June decision (19-05-042).

PG&E was heavily criticized for failures in preparedness and communication when it blacked out 2.4 million residents in October. Officials, including Gov. Gavin Newsom and his appointee Batjer, have insisted the situation can’t reoccur. (See California Officials Hammer PG&E over Power Shutoffs.)

The utility is in bankruptcy following two years of catastrophic wildfires in 2017 and 2018 that killed dozens of people and destroyed thousands of structures. It mostly avoided a repeat of the past two fire seasons in 2019, but its decision to de-energize vast swaths of Northern and Central California for days at a time caused controversy.

CEO Bill Johnson told state lawmakers in November that the power shutoffs had prevented fires, though improvements were needed.

“Turning off power for safety is an effective tool and really only one of the many tools we are using,” Johnson said. “We will get better at using it.”

In her assigned commissioner’s ruling Thursday, Batjer said PG&E’s reports to the commission on the shutoffs last fall had “serious deficiencies” — and that the utility eventually stopped filing reports altogether in December because it unilaterally decided it had fulfilled its obligations to the CPUC.

The weekly reports were instituted in response to a letter Batjer wrote to Johnson on Oct. 14, citing serious “failures in execution” in the shutoffs and ordering corrective action. (See CPUC Orders Changes to PG&E Shutoff Rules.)

The reports initially took the form of letters from PG&E to Batjer, but an administrative law judge later formally incorporated the reports into the CPUC’s rulemaking on de-energization. Batjer’s ruling Thursday was part of that proceeding (18-12-005). In it she ordered PG&E to resume regular (biweekly) reports on its PSPS corrective actions and to provide the CPUC with a detailed plan in 15 days describing PG&E’s anticipated improvements and challenges regarding PSPS events in the fire season that starts this summer.

Within 45 days, the utility must update its PSPS protocols and be prepared to exercise the measures, without prior notice, in conjunction with the state Office of Emergency Services and the California Department of Forestry and Fire Prevention, Batjer said. She did not propose any penalties in her ruling.

“Based on the identified deficiencies in PG&E’s reporting on its post-PSPS corrective actions to date, I am directing further action to ensure that PG&E is adequately operationalizing the clear guidance we have provided and implementing corrective actions that will meaningfully mitigate the impact of any future PSPS,” the CPUC chair wrote.

February 4, 2020

Texas PUC Delays AEP Texas, CenterPoint Rate Orders

The Texas Public Utility Commission last week declined to issue final orders in a pair of rate cases involving CenterPoint Energy and AEP Texas, but it did approve several other rate recoveries.

During an open meeting Friday that lasted less than half an hour, the PUC signed off on nearly $6.4 million in rate case expenses for Entergy Texas (48 439) and Southwestern Electric Power Co.’s request to implement a net interim fuel refund of more than $15 million (49974).

Texas PUC — Commissioners Shelly Botkin and Arthur D’Andrea proceed without Chair DeAnn Walker.

The commission also approved a $475,000 administrative penalty against EDF Energy Services for failing to reserve sufficient capacity to meet its responsive reserve service for 113 operating hours between March 27, 2016, and Dec. 28, 2017 (50304).

Finally, the PUC approved a $10,000 fine for Shell Energy North America related to over-procurement of ancillary services (50227).

Commissioner Arthur D’Andrea said the PUC will be intervening in a pair of FERC proceedings involving MISO:

Proposed Tariff revisions to expand, modify and clarify the identification and cost allocation of transmission facilities providing regional and local economic benefits to MISO customers (ER20-857, ER20-858, ER20-862).
A proposal to remove the exemption from physical withholding penalty charges for resources not categorized as planning resources (ER20-665, ER20-668, ER20-669).

Chairman DeAnn Walker missed the meeting with an undisclosed illness. D’Andrea chaired the meeting in her absence.

— Tom Kleckner

February 4, 2020March 12, 2025

NEPOOL Markets Committee Briefs: Jan. 28, 2020

ISO-NE’s External Market Monitor last week presented the New England Power Pool Markets Committee a conceptual design for mitigating market power in the RTO’s day-ahead ancillary services market.

Monitor David Patton led off with a memo describing the advantages of the conduct-impact approach, a two-step process that uses reference levels to test both a participant’s conduct as it relates to a competitive norm and its impact on the market.

The first part of the test considers whether a unit’s offer exceeds its reference level by some pre-established threshold. If the threshold is exceeded, then a second part of the test determines whether the conduct (i.e., the offer) has caused an impact on the market clearing price for energy or ancillary services or affected an uplift payment.

Patton said the conduct-impact framework has been effective in protecting MISO, Monitor Strengthening Mitigation Measures.)

“Our general recommendation is that the conduct-and-impact framework should be applied to the day-ahead ancillary products and should be effective at addressing the market power concerns,” Patton said.

“The nice thing about the conduct-and-impact mitigation framework is, if the market is very competitive, it will rarely if ever mitigate any offers, but the fact that it exists … actually does discipline the behavior of the suppliers of the products,” he said. “We think that this framework, regardless of the outcomes of the simulation analysis, will be effective to mitigate the potential competitive concerns.”

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]

In addition to various components of short-run marginal costs, suppliers’ offer prices can be affected by their varied expectations around LMPs, risk preferences and price volatility, even if they have no market power, Patton said. Those differences can prompt suppliers to submit offers that vary substantially from supplier to supplier.

Under the ISO-NE External Market Monitor’s framework, the RTO would use a pre-established price threshold to check participants’ market power. | Potomac Economics

In his presentation, Patton pointed out that price volatility can cause suppliers to limit their exposure by adding a risk premium, to reduce the likelihood of covering an option at a loss. He said reasonable risk premiums should be allowed.

Such latitude would require a model to estimate the variation in such premiums to ensure that the pre-established thresholds accommodate the variation under a wide range of conditions, he said. Setting the thresholds appropriately can change the incentives of suppliers to offer more competitively, with the analysis showing that a pivotal supplier does not have an incentive to raise prices under conduct thresholds of $50/MWh.

The EMM recommended ex post market power mitigation measures to deter physical withholding and provide an alternative to a must-offer obligation. He said the most common forms of such measures are financial sanctions based on the impact of a market participant’s conduct or subjecting a supplier with market power to a must-offer obligation.

“We are worried about the overstepping of bounds,” Brett Kruse of Calpine said. “Traditionally, as we saw in the California Energy Crisis, FERC’s always had the ability to look at something and say, ‘You didn’t violate any rules; you didn’t violate the tariff; you didn’t violate any NERC criteria; but what you did, at its core, was to defraud. You had the intent to defraud people.’ … And they’ve held people accountable for that.” He pointed out that the ex post mitigation that Patton is proposing would occur many months after decisions on LNG arrangements were made and that the Monitor had effectively proposed a “backdoor” must-offer requirement.

“By definition, most exercises of market power do not violate any rules; it’s not fraudulent,” Patton said. “I’m an economist, and if you have market power, I expect you to attempt to exercise it. If you’re a rational economic actor in a market, and you have market power, you exercise it. In fact, you’re under an obligation to your shareholders to exercise market power, which is why market power mitigation must be effective.”

“FERC set up these markets with the notion that people were going to exercise market power, that we were going to get noncompetitive pricing, so either people have to not have market power, or it has to be effectively mitigated,” Patton said.

Market Power Assessment

ISO-NE is also making progress on the market power assessment (MPA) being conducted concurrently with the mitigation design work, Chief Economist Matt White said. (See “Market Power Analysis and Mitigation,” NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.)

An MPA should determine whether market power is empirically supported, and if so, help to identify the specific conditions, frequency and extent to which individual participants may be able to profitably exercise market power, White said.

RTO staff have largely completed the first of four steps in the MPA, White said, presenting a memo.

The four major steps are: developing co-optimized market clearing software; producing study cases and input data; modeling participants’ option offers; and evaluating and analyzing of the market clearing outcomes.

White said the RTO is developing, coding and validating a day-ahead co-optimized market clearing engine model, or study model, by itself because the vendor would not be able to do so before 2024.

After the RTO assembles the data, White said, it must develop the assumptions and construct the offer behavior, using actual numbers, which has to be done under two scenarios: competitive conditions, and conditions in which a participant is able to exercise market power.

The model incorporates the functions and logic of the existing day-ahead market and includes the proposed new day-ahead ancillary services, pricing and co-optimization clearing logic.

ESI Central Case Update

Results for the critical winter months — or Central case — in the RTO’s latest model of its Energy Security Improvements initiative reflect limited changes in assumptions relative to those presented at the prior January MC meeting, Todd Schatzki of Analysis Group said.

The RTO has until April 15 to file a long-term fuel security mechanism with FERC (EL18-182). The Participants Committee plans to vote on the new market design at its April 2 meeting.

Modifications included minor changes to the hourly strike price inputs used in all cases and extending the date of the last barge refueling from Feb. 1 to 14, expanding the available fuel supply. In the cold snap of 2017/18, sea and river ice affected ship and barge deliveries to fuel oil terminals located in Maine and New Hampshire and on the Hudson River.

ESI increases total customer payments in some cases (Frequent, Infrequent) and decreases it in others (Extended). | Analysis Group

Changes result in minor decreases in total customer payments in the Frequent and Infrequent cases, with other results similar to those reported on Jan. 14. The full set of tables is provided in the presentation appendix, Schatzki said. (See NEPOOL Markets Committee Briefs: Jan. 14-15, 2020.)

Customer payments increase because of forecast energy requirement (FER) payments plus the net cost of new day-ahead energy options, with the higher payments partially or more than fully offset by reduced energy (LMP) costs caused largely by the incremental energy inventory under the market design, he said.

The new analysis showed that in the “frequent” stressed conditions scenario, total payments by load would increase 3.2% to $4.23 billion, with $250 million in FER payments and $66 million in net day-ahead option payments partially offset by a $184 million reduction in payments for energy and real-time operating reserves.

Under the “extended” stressed conditions case — based on 2017/18, with its one long cold snap — load costs would decrease $62 million (-2.3%) to $2.66 billion.

The “infrequent” stressed conditions case, based on 2016/17, showed $1.8 billion in load costs, a $35 million (2%) increase.

— Michael Kuser